The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.
This invention relates to compositions and methods for treating subterranean formations, in particular, compositions and methods to mitigate annular pressure buildup in subterranean wells.
During the construction of a subterranean well, one or more tubular bodies, such as casings or liners, are installed to support the borehole and provide a conduit through which hydrocarbons or other formation fluids may flow to the surface for recovery. Usually, each pipe string extends to a greater depth than its predecessor, and has a smaller diameter than its predecessor. Primary cementing is usually performed after the installation of each pipe string. This involves placing cement slurry in the annular region between the exterior surface of the pipe string and the borehole wall, and allowing it to harden. The set cement is substantially impermeable, and bonds to the pipe and the borehole wall. Thus, the set cement supports the pipe string and provides hydraulic isolation. Hydraulic cements, usually Portland cement, are typically used to cement the tubular bodies within the wellbore. Remedial cementing operations may also be conducted, involving plugging highly permeable zones or fractures in wellbores, plugging cracks and holes in pipe strings, etc.
As mentioned above, multiple casing strings are usually concentric; thus, there are annular spaces between them. Normally, each annular volume between the casing strings is filled to some extent with fluid that was present in the wellbore when the casing was installed. The entire annulus between the casing strings is not usually cemented; however, in many cases, set cement does seal the bottom portion of each annulus.
Formation-fluid production from a well is initiated after the strings of tubulars have been installed and primary cementing operations have been completed. The formation fluids may include crude oil, natural gas liquids, petroleum vapors, synthesis gas (e.g., carbon monoxide), other gases (e.g., carbon dioxide), steam, water or aqueous solutions. The temperatures of formation fluids are usually higher than those further uphole. In such cases, as formation fluids travel toward the production facility, they heat the pipe strings and the surrounding wellbore. This will in turn raise the temperature of fluids inside the annuli between the pipe strings, and the fluids will tend to expand.
In many cases, such as wells on land, the fluid expansion may be relieved at the surface. However, in offshore-well situations in which the wellhead is submerged, both the top and bottom of each annulus may be sealed. A typical scenario is shown in a cross-sectional diagram (FIG. 1). A series of successive, concentric casing strings 1 has been installed in a subterranean wellbore. The cement sheath 2 covers the annular region between each casing string and the formation 3. Only the casing string with the widest diameter has been cemented to surface. The other strings are not cemented to surface—only the regions between those casings and the formation are covered by the cement sheath. This leaves annular regions 4 that are not completely cemented; instead, they are filled with other well-completion fluids such as drilling fluid, spacer fluid, chemical wash and completion brine. Further uphole, the annuli are sealed to prevent the fluids contained therein from leaking into the environment.
Under these circumstances, there is no outlet for annular-fluid expansion. When the formation fluids heat the fluid trapped in the annulus between the casing strings, the resulting expansion may pressurize the annulus to a level that would cause severe wellbore damage, including damage to the cement sheath, the casing, tubulars and other wellbore equipment. This process is known in the art as annular pressure buildup (APB). The industry has attempted to solve the APB problem in a variety of ways.
Foamed fluids have been used; however, operators have encountered difficulties placing them near high-permeability formations In addition, the foam may not be stable over the long term, leading to breakout of the gaseous phase and a reduction of the fluid's ability to compensate for pressure fluctuations.
Another fluid system contains a polymerizable monomer, for example methyl methacrylate (MMA). After placement in the annulus between two casings, the MMA is made to crosslink when annular temperature increases due to production of hot formation fluids. The resulting polymer is significantly more dense than the monomer; as a result, the fluid volume decreases, and the pressure inside the sealed annulus also decreases. The amount of monomer is chosen such that the pressure decrease in the annulus will be sufficient to mitigate the APB. The fluid may comprise a gas-generating agent. Liberation of gas inside the sealed annulus after fluid placement provides a compressible gas pocket. The fluid may also comprise a porous foam material such as polystyrene or polyurethane.
Syntactic foam is a wrapable or sprayable foam that is impregnated with cenospheres or glass microspheres. The foam typically covers the tubular body across the interval where APB is anticipated. The hollow spheres are designed to rupture at a predetermined pressure, creating more volume in the annulus. However, this approach is problematic for two reasons. First, the foam may break off during the tubular-body installation, creating obstructions in the annulus that may impede proper fluid placement. Second, the foam is not resilient—it works only once to reduce annular volume.
Fluids that contain hollow glass microspheres have been reported. The glass microspheres are available in several grades with failure ratings between about 4,000 and 10,000 psi. Operators choose grades that are most appropriate for the anticipated APB. This approach can be problematic when the microsphere-containing fluid is pumped around a casing shoe during a primary-cementing operation. The bottomhole pressure may exceed the collapse pressure of the glass spheres, and the resulting collapse of the spheres destroys the utility of the fluid. Situations may also occur in which an operator chooses a grade of microspheres that can survive the bottomhole pressure, but the anticipated APB further up the annulus is lower than the microsphere-failure rating. In such situations, the microspheres will not rupture when needed to control APB, potentially resulting in casing failure.
Several mechanical methods for controlling APB have been developed, including burst disks and hollow centralizer elements. Once ruptured, burst-disk assemblies may require well reentry for replacement. Such operations involve considerable downtime which can be very expensive in offshore environments. Hollow centralizer elements are sealed by valves or rupture disks. When APB occurs, the seals rupture and allow fluid influx into the hollow element to relieve the pressure. These centralizers provide a limited amount of volume mitigation, and the effects of fluid influx on the structural integrity of the centralizer is unclear.
It is therefore desirable to develop a system for controlling APB that overcomes the problems mentioned above.